Thank you for standing by, and welcome to Comstock Resources second quarter fiscal year 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one one on your telephone. I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.
All right, thank you. You got a good tone this morning. You start everybody off right. Let me tell you, we're thankful to be a natural gas producer in the Haynesville, which we think is the best basin in North America to have dry natural gas. Anyhow, welcome to the Comstock Resources second quarter 2022 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation titled Second Quarter 2022 Results. I'm Jay Allison, the Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations.
If you'll flip over to two, please refer to slide two in our presentation to note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now starts the real presentation. Slide three, the second quarter 2022 highlights. We cover the highlights of the second quarter on slide three. In the second quarter, we generated $190 million of operating free cash flow. We also retired $271 million of our senior notes, including the redemption of our 7.5% senior notes we assumed when we acquired Covey Park, and we repurchased just $26 million of our 6.75% senior notes in the open market.
We brought our leverage down to 1.2 times. Our EBITDAX for the quarter came in at $515 million or 105% higher than last year. Our operating cash flow increased 133% to $458 million or $0.65 per diluted share. Revenues after hedging for the quarter were $604 million and 86% higher than last year. Our adjusted net income for the quarter was $274 million or $1 per diluted share. Our Haynesville drilling program is going well, as demonstrated by the 14 or 12.6 net operated wells that we reported on this quarter, with an average initial production rate of 26 million cu ft per day.
We completed a very attractive bolt-on acquisition, which included approximately 60,000 net acres prospective for the Haynesville and Bossier Shale and a 145-mile high pressure pipeline and natural gas treating plant for $36 million. We also achieved certification for our natural gas production under the MiQ standard for methane emissions measurement, which demonstrates our environmental stewardship. I will now turn the call over to Roland Burns to comment on our financial results. Roland.
All right, thanks, Jay. On slide four, we recap the very strong financial results we had for the second quarter. Pro forma for the sale of our Bakken properties, which we completed last October, our production increased by 1% to 1.4 billion cubic feet equivalent per day. On a pro forma basis, our adjusted EBITDAX for the quarter grew by 122% over 2021's second quarter to $515 million, and it was driven mostly by stronger natural gas prices. We generated $458 million of cash flow during the quarter, a 159% increase over 2021's second quarter on a pro forma basis. Our cash flow per share during the quarter was $1.65, up from $0.71 for the second quarter of 2021.
Our adjusted net income for the second quarter was $274 million, a 454% increase from the second quarter of 2021, and earnings per share came in at $1, as compared to $0.20 in the second quarter of 2021. We generated $190 million of free cash flow from operations in the quarter, 586% higher than the second quarter of last year. The growth in EBITDAX and the retirement of our senior notes in the quarter drove a substantial improvement to our leverage ratio, which improved in the quarter to 1.2x, down from 2.9x in the second quarter of 2021. Improved natural gas prices were the primary factor driving the strong financial results in the quarter.
A breakdown of our gas price realizations is presented on slide five. During the second quarter, the quarterly NYMEX settlement price averaged $7.17, and the average Henry Hub spot price averaged $7.39. During the quarter, we nominated 83% of our gas to be sold at index prices tied to the contract settlement price, and we sold the remaining 17% of our gas in the daily spot market. Therefore, the expected NYMEX reference price for our sales in the second quarter would have been $7.21. Our realized price during the second quarter averaged $6.93, reflecting that $0.28 Differential. Our differential stayed tight in the quarter, as we only have 10% of our production subject to the wider regional indexes at Perryville and Carthage.
In the second quarter, we were 54% hedged, which reduced our realized price to $4.85. We also generated $2 million of margin from third-party marketing in the quarter, which added $0.02 to our average price realization. On slide six, we detail our operating costs per Mcfe and our EBITDAX margin. Our operating costs per Mcfe averaged $0.74 in the second quarter, $0.05 higher than our first quarter rate. The increase is directly related to the higher natural gas prices we're realizing, as production taxes increased by $0.06 in the second quarter. Our gathering costs increased by $0.02 in the quarter, which was primarily due to the impact of higher fuel costs or the higher value of natural gas that's used in transportation. That was offset by a $0.03 drop in our other lifting costs.
Our G&A costs came in at $0.06, the same as our first quarter rate. Our EBITDAX margin after hedging came in at 85% in the second quarter, up from 81% in the first quarter. On slide seven, we recap our first half of this year, spending on drilling and other development activity. In the first six months of this year, we spent $487 million on development activities, including $426 million on our operated Haynesville and Bossier Shale drilling program. $263 million of our CapEx was spent in the second quarter. In the first half of this year, we've drilled 31 wells or 27.7 net wells, operated horizontal Haynesville wells, and we've turned 36 or 29.1 net operated wells to sales.
These wells had an average IP rate of 26 million cu ft per day. We also had an additional 1.2 net non-operated wells that we turned to sales in the first half of this year. Slide eight recaps our balance sheet at the end of the second quarter. We had $350 million drawn on our revolving credit facility at the end of the second quarter, after having used the revolver to fund part of the redemption of our 2025 senior notes on May 15th. We also repurchased $26.1 million in principal amount of our 2029 senior notes at a discount for $25 million during the quarter. In total, we retired 271 million in principal of senior notes during the second quarter.
The reduction in our debt and the growth in our EBITDAX drove our leverage ratio down to 1.2 times in the quarter as compared to 2.9 times in the second quarter of last year. We plan on retiring the remaining $350 million outstanding on a revolver later this year using free cash flow from operations. We ended the second quarter with financial equity of almost $1.1 billion. I'll now turn the call over to Dan to discuss the operations.
Thanks, Roland. Over on slide nine, this just shows our average lateral length for the wells we've drilled since 2017. Our lateral lengths averaged 9,612 ft in the second quarter on the 16 wells that we turned to sales. Among the 16 new wells were five extra long wells with laterals greater than 11,000 ft, with the longest lateral this quarter coming in at 12,237 ft. To date, we have drilled nine 15,000-foot laterals. Four of these have been turned to sales. We've got three that are currently completing and two that are waiting on completion. We're also in the process of drilling our tenth 15,000-foot lateral. The longest lateral drilled and completed to date stands at 15,291 ft.
By year-end, we anticipate turning 69 gross wells to sales with an average lateral length of 10,050 ft. Eighteen of these wells are expected to be longer than 11,000 ft and nine of the wells being 15,000- foot laterals. We've been really pleased with our progress to date, drilling these 15,000-foot laterals. They're playing an increasing role in offsetting some of our cost increases we're experiencing in this inflationary cost environment. Slide 10 shows our latest D&C cost trend through the second quarter for our benchmark long lateral wells. These include all our wells with lateral lengths greater than 8,000 ft. 13 of the 16 wells that we turned to sales during the quarter were long laterals.
Our D&C cost averaged $1,262 per foot in the second quarter, representing a 12% increase from the first quarter and a 21% increase from our average 2021 D&C cost. Our drilling costs were $478 a foot, or a 6% quarter-to-quarter increase, while our completion costs increased 17% quarter to quarter up to $784 a foot. The cost increases we experienced during the second quarter were purely driven by the cost inflation we're seeing across the basin. On slide 11, this is a summary of our second quarter well activity. Since the last call, we have turned to sales 14 additional wells.
The wells were drilled with lateral lengths ranging from 5,373-12,237 ft and had an average lateral of 9,577 ft. The individual wells were tested at IP rates ranging from 12-37 million cu ft a day, with the average IP settling in at 26 million a day. Second quarter results also include the completion of the first wells drilled on our western Haynesville acreage in Robertson County, Texas. The Circle M number 18 well was completed in the Bossier Shale with a 7,861-foot lateral. The well was tested at 37 million cu ft a day and has been flowing for approximately 90 days with an average rate of 30 million a day.
Now to direct you to slide 12, where we discuss our natural gas powered completions with the BJ TITAN fleet. Back in April this year, we deployed our first TITAN fracturing fleet, which is fueled by 100% natural gas. On the first two pads that were completed using the TITAN fleet, we eliminated 1.4 million gallons of diesel fuel, replaced by cleaner burning natural gas. The environment was positively impacted by removing approximately 2,000 metric tons of greenhouse gas emissions. In addition to drilling the longer laterals to help offset our higher cost of services, this fleet has played a key role in helping us minimize our completion cost as the cost of diesel has increased significantly. The completion costs on those first two pads were reduced by 15% compared to using one of our conventional diesel fleets.
Based on the initial results, we have recently entered into a contract with BJ Energy Solutions for a second Titan natural gas powered fleet, and we expect this to be in service in the first quarter of 2023. I'll now turn it back over to Jay to summarize our 2022 outlook.
Thank you, Dan, and thank you, Roland. If you go to 13. I would direct you to slide 13, where we summarize our outlook for the rest of the year. We are on pace to generate significantly more than our targeted $500 million of free cash flow, which at current commodity prices could approach $1 billion. The first priority of the free cash flow generation remains the reduction of our debt level, to pave the way to reinitiate a return of capital program. We did redeem $244 million outstanding on our 2025 senior notes on May 15th, and we repurchased $26 million of our 2029 senior notes at a discount to par in June. We expect to repay the $350 million remaining borrowing outstanding under our bank credit facility by year-end.
We are investing a little more in our Haynesville drilling program by adding two operated rigs before the end of the year, which will drive additional production growth in 2023. We're also earmarking $50 million-$75 million for bolt-on acquisitions and leasing activity for this year, which includes the $43 million already spent in the first half of this year. Even with our additional investment in our future growth and our plans to repay an additional $350 million of debt, we will have substantial free cash flow to start our return of capital program. We have now exceeded the leverage goal we set and now expect to reinstate our shareholder dividend during the fourth quarter of this year. Lastly, we will continue to maintain and grow our very strong financial liquidity.
I'll now have Ron provide some specific guidance for the rest of the year. Ron?
Thanks, Jay. On slide 14, we provide updated financial guidance for 2022. Third quarter production guidance is 1.37-1.44 Bcfe per day, and the full year guidance remains unchanged at the 1.39-1.45 Bcf a day we provided back in May. During the third quarter, we currently plan to turn to sales 11-15 net wells. Our development CapEx guidance is $925 million-$975 million, which incorporates the addition of two rigs, and is up from the $875 million-$925 million we provided in May. The 2022 wells have an average lateral length that's about 14% longer than last year, which is helping to offset some of the cost inflation.
In addition to what we spend on our drilling program, we could spend up to a total of $50-$75 million on bolt-on acquisitions and new leasing, which includes the $43 million we have already spent this year. Our LOE is expected to average $0.20-$0.25 per Mcfe, both in the third quarter and the full year, while our gathering and transportation costs are expected to average $0.26-$0.30 per Mcfe in both third quarter and the full year. With the higher prices for natural gas, our production and ad valorem taxes are now expected to average $0.16-$0.18 per Mcfe, while our DD&A rate is expected to average $0.90-$0.96 per Mcfe for the year.
Cash G&A is expected to be $7-$8 million in the third quarter and $29-$32 million for the full year, while the non-cash portion of our G&A is expected to total approximately $2 million per quarter. Cash interest expense is expected to total $38-$45 million in the third quarter and $152 million-$160 million for the full year, which includes the impact of the redemption of our 2025 notes in May. On the tax side, our effective tax rate is still expected to average 22%-25%, and we still expect to defer 75%-80% of our taxes.
This year. I'll now turn the call back over to the operator to answer questions from the analysts who follow the company. Keith.
Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from the line of Austin Aucoin of Johnson Rice & Company. Austin Aucoin, your line is open.
Good morning, Jay, and to your team. Congrats on a strong quarter.
Thank you.
My first question is, with the second TITAN fleet expected to be in service in 1Q2023, is that a good timeframe for the additional two rigs, or should we think that they'd be, y'all are trying to get them earlier?
The two rigs, we got one that's just started, got underway, and the second additional rig is coming later this month, into this month. Q1 of 2023 for the next Titan fleet is accurate. Now, remember, the first Titan fleet we were supposed to have received in January of this year, and we didn't get it till April. That's the guesstimated date right now.
Thank you. I appreciate that. As a follow-up, you showed impressive results from your Circle M well in Robertson County. Could you provide some more details as to why this was chosen for the step-out of the exploration? And as a follow-up, how many locations do you see on the acreage?
Yeah, let me, you know, we've managed like this step-out on the Circle M. We've managed our management style has been like this numerous times. If you follow us a long time, if you go back to 2015, you know, we drilled a Bossier well in the DeSoto Parish when it wasn't popular to drill Bossier wells, and we had drilled eight successful Haynesville wells before that. We wanted to test the Bossier, and that kind of kicked off a Bossier program. Five years ago, you know, we had a footprint in Caddo Parish, and we wanted to test it, and we drilled several wells, and it turned out to be nice. Same thing in Harrison County five years ago.
We wanted to firm up our position there, and that worked. Even if you go back even to this last quarter, we drilled three wells in Nacogdoches, where one was a Bossier, two were Haynesvilles, and we're bringing those online today, and those look really good. We've really stepped out on the same thing with the Circle M. You know, our team wanted to see if we could technically drill a well out there. It looks good. We reported it. You know, one well is only one well. We'll test our technology on the next well, and, you know, we call this a starter well.
Thank you. I appreciate the color. That's all for me.
Thank you. Our next question comes from the line of Umang Choudhary of Goldman Sachs. Umang Choudhary, your line is open.
Hi. Thank you. Good morning, and thank you for taking my questions. My first question is on production outlook. Your guidance calls for a step-up in production in fourth quarter. Wanted to get your thoughts on cadence of completions in the second half. Also, given you have added two rigs in 2023, any initial read on production next year would be really helpful.
Yeah. On production, we see obviously more completions. I think we're kinda expecting, you know, around 19 or so wells coming online in the fourth quarter and about 14 or so in the third quarter. Currently, you know, of course, a lot of it depends on when they come on in the quarter. You know, we have seen kinda longer drill times just due to inefficiencies just out there due to supply chain issues. I think that's kind of, you know, pushed some of the production a little bit later in the year this year, but we do see getting all these wells online, you know, that we kind of have planned for this year.
It's early for us to start giving a lot of guidance for 2023 production, but, you know, we are obviously adding, you know, more rigs. As we get, you know, probably maybe it'll be later on in the year, we'll kinda give a really good outlook to what we expect for next year.
Got it. That's really helpful. Acknowledging that you sell most of your volumes on the Gulf Coast markets, I wanted to get your thoughts on the recent Perryville differentials. What is driving the weakness, and, when do you expect that to be alleviated?
Yeah, I think you're talking about, you know, higher bases, you know, differentials there at the main regional hubs, you know, Perryville and Carthage. You know, I think those are really reflect the tightness of transportation in the Haynesville, you know, that we've seen, you know, as you know, production has increased some there. There's also been, you know, more kind of a little bit more maintenance than normal going on, which has, you know, aggravated the situation. We see some of that loosening up as we get into October, as far as the maintenance being over and, you know, some new capacity coming to the, you know, the basin to alleviate a little of the tightness.
Given the tight market and you know the you know that's why you've seen the differentials you know especially at Perryville you know be volatile and maybe elevated here. That's what you know we've expected this for years and you know really have moved to lock in a lot of our gas sales to Gulf Coast Indexes and got more access to transportation to be able to deliver gas to the Gulf Coast Indexes. We still have you know somewhere around 10% of our basis still that's subject to the wider differentials.
You know, even some of the gas we sell at Perryville , we've tried to do it under longer term sales agreements where we, you know, we've been able to to lock that in closer to that $0.20-$0.25 area that it has been historically. That's served us pretty well, you know, this summer.
Well, to Roland's point, you know, we are selling gas directly to every LNG facility in Louisiana.
Yeah, we see that increasing, especially as we go into next year and we continue to engage in talks. We wanna be a big supplier, you know, to especially the Louisiana LNG shippers, as we have a lot of gas that we can deliver, you know, to them. That's the ultimate driver of demand in our region. You know, that's where we can probably get, you know, the best price realizations.
You know, we market over 2 Bcf a day and produce right at 1.4 Bcf. If you look, we have about 1.7 Bcf a day with direct access to, as Roland said, this premium Gulf Coast market and sales.
Yeah, you noticed in kind of this year, we've had you know we've added some additional income through marketing third-party gas. That's really because we do have some extra capacity in some of our Gulf Coast transport that we're not able to use yet for our equity production. As we have that excess capacity and you know the difference between the Gulf Coast indexes and the regional differences have been pretty significant. We've been able to go to some third parties and help them get a better price and then also make some margin for ourselves by using some of that capacity. As we need that capacity, as our production grows in the area, you know, we'll just use it for our equity gas first.
Grant, Roland mentioned, I mean, we've probably through David Winsness and the marketing group, Whitney, et cetera, you know, we try to preplan this for a year and a half out. We have 400,000-plus acres, and that footprint really provides us a lot of flexibility to optimize the drilling activity where we're gonna put these wells and drill them.
No, great color. Thank you so much for your response. Thank you.
Thank you. Our next question comes from the line of Neal Dingmann of Truist Securities. Your question, please, Neal Dingmann.
Morning, guys. The two rigs that you talked about arriving later this year, Jay, I'm just wondering, I know it's early, any thoughts on the tenure of these rigs and, you know, what type of contracts you would lock into these rigs?
This is Dan. Yeah, we've all of our rigs we got now are on either basically well-to-well contracts or six-month contracts. You know, the rig companies have been reluctant to enter any long-term contracts, just in the kinda recent past here. You know, we're looking at rates that are up probably overall. I mean, you're approaching 50% from, you know, a year and a half ago or so. You know, just kinda seeing where the market goes. I mean, we're gonna kinda sit where we're at status quo for the moment and, you know, go from there as far as deciding on long-term contracts.
Yeah, Dan, I think that makes a lot of sense. Just lastly, next question on LNG. Specifically, you all continue to be positioned very well. Jay, you pointed out early, I think, given the basin and to benefit from potential LNG projects. I'm just wondering, again, I know it's early, not a lot going on, but could you give any color on just any potential new LNG contracts you might be seeing out there?
You know, we've visited with all the major LNG exporters. I mean, because I think we have more undedicated gas than any other Haynesville producer. You know, what we're trying to do, we're trying to have enough uncommitted current volume to support transportation and long-term sales with a partnership, et cetera. We wanna have, you know, if a LNG company comes in, we wanna show them we have 1,600 net locations in the primary area. We have takeaway. You know, we have 400,000 net acres prospective. We do market a lot of gas. I mean, we have, you know, I think one of the key things is we've been in this area since probably 1991, so we have relationships with every midstream provider.
I think we have everything that they would want. The question is, what do you do with pricing? Do you expose yourself to international pricing? As arbitrage, as an endgame, do you do Henry Hub, you know, 115%, et cetera, which that's what 80% of the contracts look like. We just wanna be in a position to have a competitive advantage for the stakeholders that we have when LNG continues to blossom. I mean, you know, we're looking as probably your numbers, we between now and maybe 2026, we expect the LNG port to increase off the Gulf Coast by maybe 6 or 7 Bcf. We know that the world demands more LNG.
If you look at even the kind of the global deal, you know, Russia exports more gas than anybody in the world, multiple of two. 80% of that is pipelines. It's still an issue with Russia, 20% is LNG. If you look at the big LNG exporters, I mean, it's the U.S., we just surpassed Qatar, and then it's Australia. Those are all facts, and we wanna be tied in with the biggest footprint, with more locations, with the most uncommitted gas, with relationships that we have to these users, and we know them. That, that's where we are. I think it's a little early in the game, but you see all these commitments.
You know, the single largest financial investment in the world, I think we heard, was Venture Global LNG's $13+ billion commitment for LNG in the Gulf Coast area. We're right in the middle of this good storm. That's where we wanna stay and continue to de-risk our footprints.
Well said, Jay. Thank you for your time.
Thank you.
Thank you. Our next question comes from Leo Mariani of MKM Partners. Your question, please, Leo Mariani.
Hey, guys. Wanted to follow up on the addition of the two rigs. Just wanted to kind of make sure I understand where we're at. Were you guys at five rigs prior to these two new rigs, and that gets you to seven? You know, is that right? It sounds like you're signaling that these two rigs would stay in place for all next year. So it sounds like a fairly good step up in activity if that's the case, and seems like that would lead to kind of much higher production growth. I know you guys had talked about kind of low- to mid-single-digit growth. Looks like this maybe could put you closer to double digits here. Any thoughts on that?
Leo, I think again, we're gonna add the two rigs as Dan answered the question earlier, which is the first question that was asked. We're gonna add the two rigs. We do think there's gonna be a demand, you know, in 2023 for more gas. This will not impact materially our production of gas in 2022, but you'll see it grow in 2023. You know, we still have that 4% production growth, I think, in 2022. We don't give a number for 2023 right now.
No, Leo, we were at seven rigs, you know. I mean, if you go back, I mean, we've been at seven rigs for a good bit of this year. This would increase our operated rig count to nine. Now, one of these nine rigs, I would say, you know, half of an entire rig during this entire year is doing third party drilling for, you know, for the Joneses. It's. We're probably really eight and a half rigs, kind of, is kind of where we end up, you know, as far as the cadence for the company. That's the kind of activity we wanna carry into 2023.
Okay. At the end of the day, like, when you guys look at the decision to kind of step up the rig count, obviously the whole, you know, natural gas, you know, strip futures curve has kind of moved up here. I'm sure that's a key part of it. But are you also gonna try to center, you know, some of this incremental activity in some of the new acreage you picked up in East Texas? And obviously, you know, Circle M Well is only one well, but, you know, looks good so far. Are there plans to kind of drill a bunch of others in that area?
I think it's too early to tell. You know, as we said, we've got a starter well. You know, we had a starter well in Caddo. We drilled some more. We had a starter well in Harrison County. We drilled some more. Rockcliff had a starter well in Panola. They drilled a bunch of them. We had a big footprint of acreage in Nacogdoches, and for 2019, 2021, we didn't drill one acre. We just drilled three wells, two Haynesville, one Bossier, and they look really good. It's too early to say what we'll do with that.
Okay. Could y'all just comment on hedging real quick? Noticed you didn't really hedge anything, you know, versus the last update. Obviously, you know, prices have been, you know, pretty darn strong here, you know, thus far this summer. Just any update on hedging philosophy? I know you've got hedges that kind of last into the first half of next year, and then you're sort of naked after that.
Yeah, that's correct, Leo. We're kind of hedged through the first half of next year. In 2023, you know, our hedge position is more in wide collars, you know, with, you know, kind of a, somewhere around a $3 floor, a little less than $10 ceiling. We're much more exposed to the full, you know, gas prices in 2023 than we are in 2022, where, you know, we're a little bit under. For the second half of the year, we're just a little bit less than 50% hedged, you know, with. I think, you know, we really looked at hedging, you know, when we put in a lot of the hedges that are paying out, we have to pay out on this year.
It was because we had a lot of leverage, and back in, after we bought Covey Park and then, you know, into a low gas price world of 2019 and 2020, you know, with the advent of COVID. You know, now that we're kind of the balance sheet is really transforming, you know, and we're gonna drive leverage under 1x, you know, we view the need to hedge a large percentage of our gas as not necessary. You know, to the extent that we do hedge in the future, it's probably gonna be more like the wide collars we did for the first half of 2023.
Okay. Thanks for the color.
Again, Leo, I think hopefully, we can get our leverage below one this next quarter. That's our goal, and hopefully, we can pay off the majority of that $350 million, which is drawn on that RBL, majority of that, I mean, the vast majority, in this next quarter. On hedges, I think, you know, we would do the same thing again. You know, when we bought Covey, we had to risk adjust everything. I mean, I think all these companies did. A lot of them put in swaps. We had swaps initially, and then we put in the collars. If you look at 2023, we're good or bad. I don't know what your opinion is, but we're one of the least hedged natural gas companies on the planet.
I mean, we'll have $3 floors and almost $10 ceilings for half of the production we have in the first half of the year, and then we're completely open to second half of 2023. You know, we committed to get our leverage ratio down. We got it down a quarter sooner than we thought to that 1.2. We committed to give shareholder return program. We're pretty close to that. In fact, we've got the leverage ratio to do that. We've committed to not, you know, we told you the last quarter, we're not looking to spend $3-$5 billion buying PDP with inventory. We think we've got a lot of inventory that's quality, and hopefully we can add some more inventory as we drill some wells.
That's been our view, and that's been our drum beat for a long time, and we've executed on it. At the same time, we wanna show you that we love the environment as much as anybody, so we've got the second TITAN, BJ TITAN natural gas frac fleet coming our way.
Okay, thanks guys.
Thank you, Leo.
Thank you. Our next question comes from the line of Fernando Zavala of Pickering Energy Partners. Your question please, Fernando Zavala.
Hey, guys. Good morning. I was wondering on the bolt-on acquisition, the infrastructure portion, is that something that you're actively looking to do more of, or was that just a one-time opportunity that came with that package?
You know what we did, and we kinda broadcasted that we were trying to do this in the last conference call. You know, toward the third and fourth quarter of last year, you know, we added some deep rights on acreage that was HBP. The shallow rights, we didn't operate. We did a transaction that we reported on, I think it was the fourth quarter 2021. All we were able to do is we were able to kinda do that same thing. It's in a broader scope. We were able to come in and acquire the deep rights on acres that are held by production. You know, we don't have to put a rig and start drilling out there immediately. It's HBP by another operator.
At the same time, you know, we did buy this 145-mile high-pressure pipeline and the natural gas treating plant for not a lot of money, really, $36 million. If you look at the future of LNG and you know the U.S. is the lowest cost provider of LNG in the world, you know, you can have the molecules, but you have to transport it. They're having trouble doing that in the Appalachia area. I mean, they may get this Mountain Valley Pipeline now built because of the Manchin deal, but who knows? I hope they do. We know that we can have midstream in our area.
This midstream pipe that we're buying in the Haynesville, they're becoming more and more valuable as demand for feed gas, you know, feedstock gas, LNG facilities grow. We looked at it, and we control it. I think our cost will be lower. We thought it was a good buy for where we're drilling, and the fact that all this is HBP. It's just a good way to spend $36 million versus, again, paying up and buying a company and adding locations if you have to buy PDP reserves.
I think on your question about would we look to do more of that, I think in specific situations where we see the opportunity, you know, to protect our cost structure and guarantee ourselves, you know, low transport costs, you know, and see that we control the gas behind it. You know, it's something we'll consider as we, you know, end this year with a very strong balance sheet and a very substantial, you know, generation of cash flow. I think this is kind of, you know, one of the things we probably wouldn't have done two, you know, three or four years ago when we wanted to spend every dollar we could on drilling.
It's something that I think is going forward and we see unique opportunities to create better markets for our gas in the Haynesville and also control, you know, keep our transport rates low. You know, we'll consider it, you know, as opportunities come up.
Yeah, again, I think it just proves to you that we think our bedrock, which is our reserves and our technical group and our marketing group and our land group, I mean, the 209 people. We think the bedrock and our reserves, that we like them. We like the area, and we like the fact that we've managed to extend this stuff into Caddo and Harrison and, you know, now into the Nacogdoches area. But that's really what we're doing. We're just sticking to basics, except this time we're not digesting a big $2.2 billion acquisition. We took that, we grew it, and this is what has been the result of it.
We think any serious low carbon outlook has to have natural gas as a fundamental resource in it. We've got the natural gas, which just has low carbon.
Got it. Thanks for that. Real quick as a follow-up, do you have an expected location count and average lateral length for the acquired acreage?
We do not.
50,000 net acres. Okay. That's it for me. Thank you.
Thank you. Our next question comes from the line of Noel Parks of Tuohy Brothers. Noel Parks, your line is open.
Can you hear me?
Yes, sir.
Yes, go ahead, Noel.
You're loud and clear.
Great. I'm sorry if you commented on this already and I missed it. With your acquisition, you also got the 145 miles of pipeline infrastructure. I was just curious about what you thought the potential benefits of that were. I'm just actually curious as to why the seller would sell that.
Well, if you look at the whole maybe 3 million acres, whatever it is, that the Haynesville Bossier encompasses, and you look at midstream is becoming more and more valuable. I mean, we could build out and, you know, we deal, I guess, with every major midstream company within that footprint, and we have for a long, long time. We can build out where the Appalachian, they're restrained from building out. We think midstream, particularly if it's long midstream, we think in a core area that's 145 miles long, it's high pressure, and it's underutilized for the most part. We think that it becomes more and more valuable.
Again, as this demand for feedstock gas for LNG facilities grows, you're gonna see the need for a lot more midstream. In fact, you know, one of the things we've been talking about during the call is the tightness of the market in the Haynesville. Most of the analysts write about how tight it is. You know, it's completely full in Appalachia. I mean, you just can't a molecule more you can really produce in a midstream. The Haynesville used to have four or five Bcf of capacity, and now it's probably 90 Bcf.
The Haynesville used to have 4 or 5 Bcf of capacity, and now it's probably 95%-99% full. We're pushing on that. At the same time, you got, you know, tens of billions of dollars of commitments for LNG export terminals along the Gulf Coast. If you add all that up, I think this midstream pipe, it's gonna be very valuable.
Yeah. No, this was just a very unique opportunity of a company that's really being dissolved, that had this asset that they weren't really utilizing. I think that this was a, you know, just a very unique opportunity that we identified a long time ago and stayed around, you know, this company that we knew was, you know, trying to, you know, dissolve and found a way to actually buy this from them in the quarter.
Yeah. As far as treating plants, you know, we already own one treating plant. I'm sorry, you said you already own one treating plant?
Yeah, we already have a.
200 million a day amine plant.
We have, you know, some gathering systems and treating plant in our North Louisiana operations too.
Oh, okay.
This will be something we could add to our Texas, yeah.
Okay. Something you can add to the Texas side. Okay, great. Did you have any significant shut-in quantities now aside from just what you would normally have for the way before fracking?
No, I think our shut-in activity, you know, it's been, you know, around this 4%, you know? It's been, you know, kind of what we expect. You know, every now and then there's maintenance or something that can be, but it's not been of long duration.
Mm-hmm.
for us so far, and we don't foresee. We see it sounding kind of similar, you know, for the rest of the year, just as we typically, you know, expect, you know, 3%-5% shut in all the time from simultaneous operations, a little bit of maintenance here and there. That's kind of what we averaged, you know, the first half of this year so far, about 4%.
Okay. Okay, great.
We do see we have seen if anything, longer to sales time frames, right? I think that's probably been the only thing that's a little different. Last year, you know, we were super efficient. You know, yeah, last year there was, you know, setting all kinds of new efficiency records for drilling days and getting wells online. This year, you know, with very busy Haynesville area supply chain, you know, we've actually seen those time frames stretch out. You know, they get done, but, you know, not near as efficiently given it's. You know, Haynesville is a very busy basin. You know, one of the bigger rig increases, the Permian and the Haynesville account for most of the big increases in rigs.
You know, that's just something we've had to deal with this year.
I'll add too that on the shut-in volumes, you know, we've Jay mentioned the tightness on the pipelines being pretty full. We have seen a little bit higher incidents of really just high line pressure from all our pipes that we're connected to have been pretty prevalent this summer. It's not really a big number and a needle mover, but it's definitely something that's been pretty predominant this summer. I'm sure it'll be you know, we'll be looking at that, you know, as we go ahead in the next year.
Like we said earlier, we'll see some expanded capacity in the Haynesville as we get into this fall, you know, that was not gonna be available this summer, so there's a little bit of relief coming there.
Right. Thanks for the extra detail. Really helps. That's all for me. Thank you.
Thank you. Again, to ask a question, please press star one one on your touch-tone telephone. Again, that's star one one to ask a question.
Thank you. Our next question comes from the line of Savannah Leonard of Bank of America. Savannah Leonard, your line is open.
Hey, guys. It's actually Gregg Brody. I just picked up Savannah's phone line. How are you today?
Hey, Gregg.
Hey. Just wanna ask a couple questions. Obviously, buying back the 7s and 2029s, I'm a bondholder. We love seeing that. It's a little bit of a surprise, so I'm curious why did you go after the 2029s. Is there a philosophy about reducing senior debt further. Then just one other question. You reduced the amount of money you were talking about spending on leasing. I'm curious why you took the steps of reducing it, that amount and not leaving that open.
Okay, those are good questions. Yeah, on the 2029s, I mean, basically, it's our most expensive debt now since we've retired the 7.5%, so it's next in line. You know, and we just saw the opportunity to retire some extra debt, you know, with fewer dollars. That was just the opportunity. I think you saw other companies in our space, you know, took advantage of that same real weakness in the trading of the bonds, you know, at the time, you know, when companies like us have incredible free cash flow. Just an opportunity we saw and took advantage of. And you know if the. Another question about the bolt-on acquisition and kind of leasing amount that we targeted.
You know, I think yeah, the year's more than half over now, and we just don't see hitting that upper end of that other number. We don't. We do expect to have some more activity, but given kinda what we just see ahead for the rest of this year, you know, I don't think we'll hit the even upper range of the $75 million for that. We just wanted to signal kinda what we're seeing. Like, we saw more deals that probably didn't happen, you know, back at the end of the first quarter. Wanted to signal that, just kind of adjustment to expectations there.
Yeah, we pulled the $100 million in. We spent, you know, the dollars, the $40+ million. There's another $20 million-$35 million or so that's kinda out there that's floating to spend.
Is it your assessment that those deals went away, or did they trade someplace else?
They're still out there. Some are gone, some are percolating. I mean, we don't expect any of them.
Yeah, a lot of it, you know, we're looking at only unique stuff that really adds to our, you know, our current footprint, you know, that expands it in a way. You know, we're not out there just in the M&A market in general looking to find any kinda assets we can.
Well, historically, the greatest way to grow is to say no. You know, 99 out of 100 times you say no, that way when you say yes, you've really been chopping to find what you're looking for. We said yes on this one. There's 60,000 net acres in the pipeline and the treating.
Yeah.
It took us a long time to say yes.
Yeah.
we said no on everything else.
That was a particular opportunity that we worked for two years.
Yeah.
It wasn't like this came.
Mm-hmm.
just came on the market or anything. It's a unique assets that we thought could fit onto ours, and we could utilize them differently than the purchaser, I mean, the seller, was doing it. We knew they were, you know, in the process of trying to liquidate the company. That was a situation we've been working on a long time, and we're excited to get it done in April.
You didn't happen to pick up any production with that, is there?
No, no production at all. It's all, yeah.
It's all.
It's all HBP'd though, so that's very important.
Yeah, that's the unique part. We actually partnered with another company who wanted to own the production. Instead of having to spend a lot of money on that, we were able to keep our expenditures, you know, for, you know, just to buy the part that we wanted. That was a very unique part of that deal.
I mean, think, 60,000 net acres, HBP, 145-mile high-pressure pipeline, and a natural gas treating plant for $36 million.
Yeah.
Yeah, it makes me cough too.
I've got that summer cold, but I did legitimately cough.
That's rough.
Just to follow up, so being optimistic about reducing debt, if you see the opportunity in the market, does that is that something we should expect going forward, or is there an absolute debt target that you are targeting?
I mean, I think, you know, of course, you know, if commodity prices stay as strong as they have, you know, there are obviously that, you know, if we have a lot of extra free cash flow, that's something that, you know, we'll consider in the future. If those two opportunities are there, we have the free cash flow, and there's a opportunity to reduce debt, you know, at a good value. We do know that we'll pay the credit facility down, so that's, you know, front and center. Something we wanna go ahead and just finish that off and this year with the second half of, you know, of the year's free cash flow.
I mean, a priority, again, like Roland said, hopefully, we can get the majority of the RBL paid off in the third quarter, probably have a little dangling in the fourth. Then, you know, we wanna continue. We'll add these two rigs, but we're not gonna add any leverage. Our goal is to give the shareholders return, period. The next thing we need to do is we need to step up and give a dividend, and then we need to continue to, you know, test our inventory, and become better at what we do. That's on top of the ground. That's the people that are drilling, completing these wells, and marketing the gas.
All right. Thank you very much for the time, guys. Much appreciated.
Yes, sir.
Thank you. At this time, I'd like to turn the call back over to Jay Allison for any closing remarks. Sir?
Okay, great. I love the questions. Thanks for your time. It's the most valuable thing you have. You know, as we look, the world LNG demand expects about 53 Bcf a day in 2022, and the U.S. provides about 22% of that, you know, 11, 12 Bcf a day. We look at that backdrop worldwide because the commodity we have is a worldwide commodity, really effective as of 2016. If you look at the worldwide energy shortage, it shows up by what? Surging coal prices, natural gas prices, and oil prices. You look at the LNG market along the Gulf Coast. I mean, we added one LNG project in 2020, and times have changed in 2022, particularly after Russia, you know, invasion.
We look at the U.S., we've got the low-cost provider of LNG in the world. We have, you know, the natural gas is the world's fastest growing fossil fuel and America's number one power source. What we wanna do is we wanna continue to de-risk our footprint, to continue to have really high margins, low costs, predictability, and continue to have a pristine balance sheet so that we can serve you. You know, you're the stakeholder, we work for you. We can serve you a return program that's predictable and have inventory that lasts for decades. We wanna be a pure company, that's our goal. Thank you for your time.
This concludes today's conference call. Thank you for participating. You may now disconnect.